Integrated gas separation-turbine CO2 capture processes

ABSTRACT

Sweep-based gas separation processes for reducing carbon dioxide emissions from gas-fired power plants. The invention involves at least two compression steps, a combustion step, a carbon dioxide capture step, a power generate step, and a sweep-based membrane separation step. One of the compression steps is used to produce a low-pressure, low-temperature compressed stream that is sent for treatment in the carbon dioxide capture step, thereby avoiding the need to expend large amounts of energy to cool an otherwise hot compressed stream from a typical compressor that produces a high-pressure stream, usually at 20-30 bar or more.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. application Ser. No.15/353,310, filed on Nov. 16, 2016, the disclosure of which is herebyincorporated herein by reference in its entirety.

FIELD OF THE INVENTION

The invention relates to membrane-based gas separation processes, andspecifically to sweep-based membrane separation processes to removecarbon dioxide from combustion gases. More particularly, the inventionuses a low-pressure, low-temperature CO₂ capture step integrated intogas-fired power plants.

BACKGROUND OF THE INVENTION

Presented below is background information on certain aspects of thepresent invention as they may relate to technical features referred toin the detailed description, but not necessarily described in detail.The discussion below should not be construed as an admission as to therelevance of the information to the claimed invention or the prior arteffect of the material described.

Much of the world's electricity is generated by coal power plants. Theseplants vent ˜800 g of CO₂ to the atmosphere for every kilowatt ofelectricity produced. These emissions are a major contributor to globalwarming. Natural gas is increasingly being used to replace coal,particularly in the United States, where the development of directionaldrilling and hydraulic fracturing has produced a large supply oflow-cost gas. Natural gas power plants vent ˜400 g of CO₂ to theatmosphere for every kilowatt of electricity produced, so switchingfuels from coal to natural gas cuts CO₂ emissions in half. However,longer-term, the emissions of natural gas power plants will also need tobe controlled if global warming targets are to be met.

A variety of technologies are being developed to separate CO₂ from powerplant flue gas so the CO₂ can be sequestered. Amine absorption is theleading technology but is costly, produces its own atmosphericemissions, requires careful operation and maintenance, and has a verylarge footprint. Membrane technology is also being developed and hasmany benefits, including lower capital and operating costs, modularconstruction, small footprint, no emissions and no changes to the powerplant steam cycle are required. However, the technology is not asdeveloped as amine, although demonstration units processing up to 20tons CO₂/day have been built.

In U.S. Pat. No. 7,962,020, we disclosed a membrane process to captureCO₂ from coal power plant flue gas. These processes use combustion airas a sweep stream in a membrane contactor. The air sweep strips CO₂ fromthe flue gas and recycles it back to the boiler. By selectivityrecycling CO₂, the concentration of CO₂ in the flue gas is increased,making its separation much easier. These processes were subsequentlyapplied to gas turbine power plants, such as in U.S. Pat. No. 8,220,247.

Natural gas turbine power plants are costly, large, and highly optimizedmachines. The expectation is that only minor modifications to theturbines will be needed so these CO₂ separation systems can beretrofitted to existing turbines. However, for new plants, the best hopefor major reductions in CO₂ capture cost is to integrate the captureprocesses into the turbine design.

One such integrated process was disclosed in our U.S. Pat. No.9,140,186, shown here in FIG. 4. An air intake stream, 406, is directedto a first compressor, 401 a. A compressed gas stream, 443, is combustedwith an incoming fuel gas stream, 416 in combustor, 402. The hot,high-pressure gas from the combustor, stream 417, is then expandedthrough the gas turbine, 403. The gas turbine is mechanically linked tothe first and second compressors, 401 a and 401 b, respectively, and anelectricity generator, 404, by shaft 405. The low-pressure exhaust gas,stream 419, from the gas turbine is still hot and sent to a heatrecovery steam generator, 420. This section includes a boiler thatproduces steam, 421, which can be directed to a steam turbine (notshown). A first portion of the gas exiting the steam generator, stream425, is routed as feed gas to sweep-based membrane separation step, 426.

Step 426 is carried out using membranes that are selective in favor ofcarbon dioxide over oxygen and nitrogen. Feed stream 425 flows acrossthe feed side of the membranes, and a sweep gas stream, 428, comprisingair, oxygen-enriched air or oxygen flows across the permeate side. Themembrane separation step divides stream 425 into residue stream 429,depleted in carbon dioxide as compared to feed stream 425, and permeatestream/sweep stream 430. The residue stream forms the treated flue gasproduced by the process. The permeate/sweep stream, 430, containing atleast 10 vol % carbon dioxide, is withdrawn from the membrane unit andis passed to compressor 101 a to form at least part of the air intakestream, 406, to first compression step 101 a.

A second portion of the turbine exhaust, stream 445, is directed tosecond compressor 401 b. The second compressed stream, 444, is thendirected to a gas-membrane separation step, 412. Step 412 uses moltensalt membranes, 446, which are selective to carbon dioxide over oxygenand nitrogen, to separate the second compressed stream, 444, into acarbon dioxide-enriched permeate stream, 413, and a carbondioxide-depleted residue stream, 414. Step 412 removes anywhere betweenat least 50% to 80%, or even 90% of the generated carbon dioxide fromthe combustor. High levels of carbon dioxide removal by step 412 are notrequired because residue stream 414 is not vented to the atmosphere, butsent back to the turbine, 403.

One disadvantage of this design, however, is that the compressed airbeing feed into the gas separation unit is extremely hot, at about 500°C. As a practical matter, this limits the CO₂ permeable membranes, 446,to very expensive inorganic materials, such as ceramics or zeolites,which can withstand high temperatures. If more readily available andlower cost polymer membranes are to be used, massive amounts of coolingof the feed gas to bring the gas to the 30-100° C. range is required.

Therefore, it would be beneficial if an integrated gasseparation-turbine process were developed that was more economical forCO₂ separation.

SUMMARY OF THE INVENTION

The invention is a process involving a sweep-based membrane gasseparation step for reducing carbon dioxide emissions from gas-firedpower plants. The sweep-based membrane gas separation step removescarbon dioxide from the turbine exhaust gas and returns it with theincoming sweep stream to a first compression step. The process alsoincludes a second compression step, a combustion step, and anexpansion/electricity generation step.

The process further includes a carbon dioxide capture step integratedbetween the first and second compression steps. The carbon capture stepinvolves treating a compressed gas stream from the first compressionstep to produce a carbon dioxide-enriched stream, which is withdrawnfrom the process, and a carbon dioxide-depleted stream, which is routedfor further compression in a second compression step prior to thecombustion step.

By integrating the carbon dioxide capture step into the turbinecompression process, considerable energy and cost savings can result.The carbon dioxide capture process could be performed on the compressedgas stream at 30 bar, as in conventional processes, but this gas isextremely hot, typically about 500 to 800° C. Cooling this gas to atemperature low enough for a conventional membrane or absorption oradsorption process that could treat this hot gas would be expensive andwould lose a significant fraction of the heat required to drive theturbo expander. By positioning the carbon capture unit at anintermediate compression stage, in the range of about 2 to 10 bar, theamount of cooling required is greatly reduced. The Benfield potassiumcarbonate process can operate at a temperature of 100 to 120° C. Somepolymeric membranes can also operate at these temperatures. This meansonly limited cooling would be required, thus considerably simplifyingthe process.

Accordingly, a basic embodiment of the present invention is a processfor controlling carbon dioxide exhaust from a combustion process,comprising:

(a) compressing an oxygen-containing stream in a first compressionapparatus, thereby producing a first compressed gas stream;

(b) routing at least a portion of the first compressed gas stream to agas separation apparatus adapted to selectively remove carbon dioxide,thereby producing a carbon dioxide-enriched stream and a carbondioxide-depleted stream;

(c) compressing the carbon dioxide-depleted stream in a secondcompression apparatus, thereby producing a second compressed gas stream;

(d) combusting at least a portion of the second compressed gas streamwith a gaseous fuel in a combustion apparatus, thereby producing acombusted gas stream;

(e) routing the combusted gas stream as part of a working gas stream toa gas turbine apparatus mechanically coupled to an electricitygenerator, and operating the gas turbine apparatus, thereby generatingelectric power and producing a turbine exhaust stream;(f) passing at least a portion of the turbine exhaust stream to amembrane separation step, wherein the membrane separation stepcomprises:

-   -   (i) providing a membrane having a feed side and a permeate side,        and being selectively permeable to carbon dioxide over nitrogen        and to carbon dioxide over oxygen,    -   (ii) passing the first portion of the turbine exhaust stream        across the feed side,    -   (iii) passing air, oxygen-enriched air, or oxygen as a sweep        stream across the permeate side,    -   (iv) withdrawing from the feed side a residue stream that is        depleted in carbon dioxide compared to the turbine exhaust        stream, and    -   (v) withdrawing from the permeate side a permeate stream        comprising oxygen and carbon dioxide; and        (g) passing the permeate stream to step (a) as at least a        portion of the oxygen-containing gas.

The compression steps may be performed using separate, discretecompressors or using a single compression train or apparatus, which hasbeen modified to allow a portion of the compressed gas to be removedfrom the compression apparatus at an intermediate stage in the train.Gas can also be introduced to the compression train at an appropriatecompression stage. The compressors are usually coupled to a gas turbineor turbines, typically on the same shaft.

After compression in step (a), the gas that is to be routed to the gasseparation apparatus will generally be at a pressure of about 2-10 bar,more preferably about 2-5 bar, and at a temperature of less than about200° C. Depending on the preferred operating conditions for the gasseparation apparatus, it may be desirable to cool the first compressedgas stream, such as by heat exchange against other process streams,before it passes as feed to the carbon dioxide removal/capture step.

The carbon dioxide removal/capture step of step (b) preferably comprisesat least one process selected from the group consisting of absorption,adsorption, liquefaction, and membrane separation, or a combination ofthese. Most preferably, the carbon dioxide removal step is a membraneseparation step. In this case, a gas separation apparatus/unit is usedthat incorporates membrane units containing membranes selectivelypermeable to carbon dioxide over nitrogen and oxygen. Various types ofmembranes may be used, but it is preferred that the membrane is apolymeric membrane.

Only a portion of the carbon dioxide in the carbon dioxide-containinggas stream needs to be removed by the carbon dioxide removal process.Some processes, for example, absorption processes, are generally mostefficient when they remove 90% or more of the carbon dioxide in the gasstream. In this case, only a portion of the feed gas would need to besent to the separation unit and the remainder would bypass theseparation unit. Other processes, such as membrane processes, are mostefficient when only 50% or 60% of the carbon dioxide in the feed gas isremoved by the membrane. In this case, the portion of the feed gas sentto the separation unit would be larger and only a small portion, ornone, of the gas would bypass the separation unit.

In the case that absorption is used, the gas separation apparatus willtypically incorporate a scrubbing column for contacting the gas with asorbent and a stripping column for regenerating the sorbent andreleasing a high-concentration carbon dioxide stream. Preferred sorptionprocesses include the Benfield process, using potassium carbonate assorbent, and amine-based processes.

Step (b) captures carbon dioxide, which is removed from the process inthe form of a concentrated stream, typically containing greater than 60vol %, 70 vol %, 80 vol %, or more carbon dioxide. This stream may besent for liquefaction, sequestration, or any other use.

In step (c), the carbon dioxide-depleted stream from carbon dioxideremoval step is compressed in a second compressor to a pressure of about30 bar and a temperature of about 500° C. or more.

Step (d) may be carried out using any combustible gas, such as naturalgas, hydrogen or syngas, or even vaporized hydrocarbon liquid, as fuel.

Step (e) is the power generation step where a gas turbine ismechanically linked to the compressors and to an electrical powergenerator. The combusted gas from the combustor is routed as part of aworking gas stream to the gas turbine to produce a low pressure, hotturbine exhaust gas. Optionally, in certain aspects, a portion of thesecond compressed stream may bypass the combustion step and be sent as adiluent stream as part of the working gas stream to the turbine.

In step (f), at least a portion of the turbine exhaust gas is passedacross the feed side of a membrane separation unit that containsmembranes selectively permeable to carbon dioxide over nitrogen and tocarbon dioxide over oxygen.

The exhaust stream flows across the feed side of the membranes, and asweep gas of air, oxygen-enriched air, or oxygen flows across thepermeate side, to provide or augment the driving force for transmembranepermeation. The sweep stream picks up the preferentially permeatingcarbon dioxide. The combined sweep/permeate stream is withdrawn from themembrane unit and directed to the combustor to form at least part of theair, oxygen-enriched air, or oxygen feed to the combustion step.

Absent the sweep-based membrane separation step, the incoming fresh airto the compressor and combustor would contain the normal atmosphericcontent of carbon dioxide (300-400 ppm). The membrane permeate/sweepstream is enriched in carbon dioxide by 2-3 orders of magnitude comparedwith atmospheric air, and will preferably contain at least about 10 vol% carbon dioxide, more preferably at least about 15 vol % carbon dioxideor even higher, such as 20 vol % or above.

It is the great enrichment of carbon dioxide in the incoming air oroxygen stream brought about by step (f) that enables thiscomposition-adjusted air stream to be tapped as the source stream forcarbon dioxide removal and capture for the overall process.

The residue stream withdrawn per step (f)(iv) forms the treated flue gasproduced by the process, and is usually discharged to the environmentvia the power plant stack. The carbon dioxide content is preferably lessthan about 5 vol %; more preferably less than about 2 vol %, and mostpreferably no greater than about 1 vol %. The reduction of the carbondioxide content to 20%, 10%, or less of the conventional content of fluegas from a gas-fired power plant greatly reduces the environmentalimpact of the plant.

The process of the invention can be carried out in all types ofgas-fired power plants. In combined cycle plants, the gas turbineexhaust gas stream can be directed through a heat recovery steamgenerator (HRSG) operation between steps (e) and (f), so that the feedgas to the sweep-based membrane separation step is the exhaust gas fromthe steam generator.

If it is necessary to cool the turbine exhaust gas before passing it tothe sweep-based membrane step, this may be done by heat exchange orotherwise in an optional cooling step. Any condensed water may beremoved from the process.

Either all or a portion of the turbine exhaust gas is then sent as feedto the sweep-based membrane separation step, and the resultingpermeate/sweep stream is returned to the first compressor in step (a).As with the embodiments described in our earlier '247 patent, a portionof the turbine exhaust stream may optionally be diverted and returned tothe compression train without passing through the sweep-based membraneseparation step.

In the embodiments discussed above, the carbon dioxide capture step andthe combustion step are performed in series. That is, the carbon dioxidecapture step occurs before the combustion step. However, it may bedesirable to perform the carbon capture step and the combustion stepsimultaneously, in parallel. In this way, an oxygen-rich gas, typicallycontaining at least 15% oxygen is sent to the combustor unit, while asecond carbon dioxide-rich gas is sent first to the carbon dioxidecapture/removal unit and then becomes diluent gas for the turbineexpander. Since the carbon dioxide-rich gas is not sent to thecombustor, its oxygen content is not important. This allows the two gasstreams to be taken from separate places in the process to maximize theoxygen content in one and separately maximize the carbon dioxide contentin the other. Thus, as an alternative embodiment, the invention mayinclude the following steps:

(a) compressing an oxygen-containing stream in a first compression step,thereby producing a first compressed gas stream;

(b) compressing a carbon dioxide-containing stream in a secondcompression step, thereby producing a second compressed gas stream;

(c) combusting the first compressed gas stream with a gaseous fuel in acombustion apparatus, thereby producing a combusted gas stream;

(d) routing at least a portion of the second compressed gas stream to agas separation apparatus adapted to selectively remove carbon dioxide,thereby producing a carbon dioxide-enriched stream and a carbondioxide-depleted stream;

(e) compressing the carbon dioxide-depleted stream in a thirdcompression step, thereby producing a third compressed gas stream;

(f) routing the combusted gas stream and the third compressed gas streamas part of a working gas stream to a gas turbine apparatus mechanicallycoupled to an electricity generator, and operating the gas turbineapparatus, thereby generating electric power and producing a turbineexhaust stream;(g) passing a first portion of the turbine exhaust stream back to thesecond compressor as at least a portion of the carbon dioxide-containingstream;(h) passing at least a second portion of the turbine exhaust stream to amembrane separation step, wherein the membrane separation stepcomprises:

-   -   (i) providing a membrane having a feed side and a permeate side,        and being selectively permeable to carbon dioxide over nitrogen        and to carbon dioxide over oxygen,    -   (ii) passing the third portion of the turbine exhaust stream        across the feed side,    -   (iii) passing air, oxygen-enriched air, or oxygen as a sweep        stream across the permeate side,    -   (iv) withdrawing from the feed side a residue stream that is        depleted in carbon dioxide compared to the turbine exhaust        stream, and    -   (v) withdrawing from the permeate side a permeate stream        comprising oxygen and carbon dioxide; and        (i) passing the permeate stream to step (a) as at least a        portion of the oxygen-containing gas.

This embodiment involves three compression steps. In the firstcompression step, a permeate/sweep stream from the sweep-based membraneseparation step is compressed as a first air intake stream to produce afirst compressed gas stream. The first air intake stream is compressedto a pressure of about 30 bar and a temperature of about 500° C. ormore. The first compressed stream is then sent to the combustor alongwith a fuel gas stream.

In the second compression step, a portion of the turbine exhaust streambypasses the sweep-based membrane separation step and is compressed toproduce a second compressed gas stream. The second compressed gas streamis compressed to a pressure of about 2-10 bar, more preferably about 2-5bar. This stream will have a temperature of less than about 200° C. Thesecond compressed gas stream is then routed to the carbon capture stepfor treatment in a gas separation apparatus.

In the third compression step, the off-gas from the carbon capture stepis compressed to produce a third compressed gas stream. This stream iscompressed to a pressure of about 30 bar and, like the first compressionstep, has temperature of about 500° C. or more. The third compressedstream is then directed as part of the working gas stream along with thecombusted gas from the combustion step to a gas turbine.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic drawing of a flow scheme showing a basicembodiment of the invention having two compression steps with a gasseparation unit integrated between the steps.

FIG. 2 is an expanded view of the gas separation section of theinvention, in which a carbon dioxide-selective membrane separation unitis used.

FIG. 3 is a schematic drawing of a flow scheme showing an embodiment ofthe invention having three compression steps.

FIG. 4 is a schematic drawing of a flow scheme showing a process usingtwo compressors (not in accordance with the invention).

DETAILED DESCRIPTION OF THE INVENTION

The term “gas” as used herein means a gas or a vapor.

The terms “exhaust gas”, “flue gas” and “emissions stream” are usedinterchangeably herein.

The terms “mol %” and “vol %” are used interchangeably herein.

The invention is a process involving membrane-based gas separation andpower generation, specifically for controlling carbon dioxide emissionsfrom gas-fired power plants, including traditional plants, combinedcycle plants incorporating HRSG, and IGCC plants. The process includesmultiple compression steps, a combustion step, and anexpansion/electricity generation step, as in traditional power plants.The process also includes a sweep-driven membrane separation step and acarbon dioxide removal or capture step. Besides generating electricpower, the process yields two gas streams: a vent or flue gas stream oflow carbon dioxide concentration that can be sent to the power plantstack, and a carbon dioxide product stream of high concentration thatcan be sent for purification and/or sequestration.

A simple flow scheme for a basic embodiment of a gas separation andpower generation process in accordance with the invention is shown inFIG. 1. It will be appreciated by those of skill in the art that FIG. 1and the other figures showing process schemes herein are very simpleblock diagrams, intended to make clear the key unit operations of theprocesses of the invention, and that actual process trains may includeadditional steps of a standard type, such as heating, chilling,compressing, condensing, pumping, monitoring of pressures, temperatures,flows, and the like. It will also be appreciated by those of skill inthe art that the unit operations may themselves be performed as multiplesteps or in a train of multiple pieces of equipment.

Turning back to FIG. 1, air, oxygen-enriched air, or oxygen isintroduced into the processes as stream 130 and flows as a sweep streamacross the permeate side of the sweep-driven membrane separation unit,127, discussed in more detail below. The permeate stream, 131, comprisesboth the sweep gas and carbon dioxide that has permeated the membranes,128, and preferably has a carbon dioxide content of at least about 10vol %, more preferably at least about 15 vol %, and most preferably atleast about 20 vol %. Stream 131 passes, with optional addition of aportion of turbine exhaust stream 120 and/or make-up air stream 132, asair intake stream 135, to compression step, 101.

The first compression step is carried out in one or multiple compressionunits, and produces compressed stream, 102, at a modest pressure in theregion of about 2 to 10 bar.

Typically, stream 102 is hot, at a temperature of about 150-200° C.Depending on the operating temperature of the separation equipment,stream 102 may be cooled by heat exchange, recuperation, or otherwise inoptional cooling step, 103, to produce cooled stream 104. Stream 104 ispreferably cooled to a temperature of about 30-100° C. Water condensedas a result of the cooling may be removed as stream 105.

Compressed stream 102 (or cooled stream 104) is directed to a gasseparation step, 106, where carbon dioxide is captured and removed fromthe process via stream 107.

Various considerations affect the choice of technology and operatingmethodology for step 106. In steady state, the mass of carbon dioxideremoved from the process in streams 107 and 129 equals the mass ofcarbon dioxide generated by combustion. Preferably, at least 50%, andmore preferably at least 80% or 90% of the generated carbon dioxideshould be captured into stream 107.

Nevertheless, very high levels of removal of carbon dioxide from thefeed inlet gas streams 102 or 104 by gas separation are not required,because the off-gas, stream 108, is not vented to the atmosphere, but iseventually directed to sweep-based membrane separation step 127. Thesweep-based membrane separation step recycles carbon dioxide in stream131, so that the carbon dioxide concentration in stream 102/104 tends tobe relatively high, such as 15 vol %, 20 vol % or more. Only a portionof this recirculating carbon dioxide needs to be removed into stream 107to achieve the target high levels of carbon dioxide capture. This is asignificant advantage of the process, as step 106 can then be operatedusing relatively low-cost, low-energy options.

Step 106 can be carried out by means of any technology or combination oftechnologies that can create a concentrated carbon dioxide stream fromstream 102 or 104. Representative methods that may be used include, butare not limited to, physical or chemical sorption, membrane separation,compression/low temperature condensation, and adsorption. All of theseare well known in the art as they relate to carbon dioxide removal fromgas mixtures of various types. However, based on the considerationsdiscussed above, the preferred technologies are absorption and membraneseparation.

Step 106 produces a concentrated carbon dioxide stream, 107, which iswithdrawn from the process. In addition to meeting the specifiedpreferred capture targets, this stream has a relatively high carbondioxide concentration, and preferably contains greater than about 60 or70 vol % carbon dioxide. Most preferably, this stream contains at leastabout 80 vol % carbon dioxide. Thus, unusually, the process achieves inone stream both high levels of carbon dioxide capture and high carbondioxide concentration.

After withdrawal from the process, stream 107 may pass to any desireddestination. The high concentration facilitates liquefaction, transport,pipelining, injection and other forms of sequestration.

The off-gas stream, 108, from the carbon dioxide removal or capture stepstill contains carbon dioxide, but at a lower concentration than thecompressed gas stream, 102/104. Typically, but not necessarily, thisconcentration is at least about 5 vol %, and can be up to about 10 vol %or even more.

Stream 108 (or stream 136) is sent to a second compression step, 109.The second compression step is carried out in one or multiplecompressors, and produces second compressed stream, 109, at a pressureof about 20 bar, 30 bar, or even higher. Although the first and secondcompression steps in FIG. 1 are shown using two separate compressors,the compression steps may be carried out using a single compressiontrain or apparatus, which has been modified to allow a portion of thecompressed gas to be introduced or removed from the compressionapparatus at an intermediate stage in the train/apparatus.

Optionally, it may be preferred that a portion of first compressedstream, 134, bypasses cooling step 103 and gas separation step 106, andis mixed with membrane residue stream 108 to form air intake stream 136before entering second compression step 109. In a membrane gasseparation process where carbon dioxide removal is only 40-70% of thecarbon dioxide in the gas, the bypass is closed. In an amine processwhere carbon dioxide removal is about 90%, then the bypass is partiallyopen and only a bit of the first compressed stream goes to theseparation unit.

Second compressed stream 110 is introduced with fuel stream 111 intocombustion step or zone 112. Natural gas, other methane-containing gas,syngas, hydrogen, or any other fuel capable of burning in air may beused. Combustion produces a hot, high-pressure gas, stream 113.

In a traditional gas-fired combustion process, the exhaust gas from thecombustor typically contains about 4 or 5 vol % carbon dioxide. In ourprocess, carbon dioxide is recycled via streams 131/133/135, asdiscussed in more detail below. As a result, the concentration of carbondioxide in stream 113 is higher than in a traditional natural gas-firedplant, and is frequently as high as at least about 10 vol %, or even atleast 15 vol %, 20 vol % or more.

Stream 113 is then sent as a working gas stream, 115, to gas turbinesection, 116. Optionally, a portion of the second compressed stream,114, may be mixed with stream 113 to form the working gas stream, 115,before being sent to the gas turbine section, 116. This section containsone or more commonly multiple gas turbines, which are coupled by meansof a shaft, 117, to compressor(s) 101 and 109, and to electricitygenerator, 118. The working gas drives the gas turbines, which in turndrive the generator and produce electric power.

The low-pressure exhaust gas from the turbines, stream 119, is stillhot, and is optionally and preferably directed to a heat recovery steamgenerator, 121. This section includes a boiler that produces steam, 122,which can be directed to a steam turbine (not shown). Gas exiting thesteam generator, stream 123, is routed as feed gas to sweep-basedmembrane separation step, 127. If it is necessary to cool the turbineexhaust gas before passing it to the membrane unit, this may be done byheat exchange or otherwise in a cooling step, 124. Any condensed watermay be removed as stream 125. After passing through optional HRSG, 121,an optional cooling step, or both, the turbine exhaust stream now passesas feed stream, 126, to sweep-based membrane separation step 127.

Step 127 is carried out using membranes that are selective in favor ofcarbon dioxide over oxygen and nitrogen. It is preferred that themembranes provide a carbon dioxide/nitrogen selectivity of at leastabout 10, and most preferably at least about 20 under the operatingconditions of the process. A carbon dioxide/oxygen selectivity of atleast 10 or 20 is also preferred. A carbon dioxide permeance of at leastabout 300 gpu, more preferably at least about 500 gpu and mostpreferably at least about 1,000 gpu is desirable. The permeance does notaffect the separation performance, but the higher the permeance, theless membrane area will be required to perform the same separation.

Any membrane with suitable performance properties may be used. Manypolymeric materials, especially elastomeric materials, are verypermeable to carbon dioxide. Preferred membranes for separating carbondioxide from nitrogen or other inert gases have a selective layer basedon a polyether. A number of such membranes are known to have high carbondioxide/nitrogen selectivity, such as 30, 40, 50 or above. Arepresentative preferred material for the selective layer is Pebax®, apolyamide-polyether block copolymer material described in detail in U.S.Pat. No. 4,963,165.

The membrane may take the form of a homogeneous film, an integralasymmetric membrane, a multilayer composite membrane, a membraneincorporating a gel or liquid layer or particulates, or any other formknown in the art. If elastomeric membranes are used, the preferred formis a composite membrane including a microporous support layer formechanical strength and a rubbery coating layer that is responsible forthe separation properties.

The membranes may be manufactured as flat sheets or as fibers and housedin any convenient module form, including spiral-wound modules,plate-and-frame modules and potted hollow-fiber modules. The making ofall these types of membranes and modules is well known in the art. Weprefer to use flat-sheet membranes in spiral-wound modules.

Step 127 may be carried out in a single bank of membrane modules or anarray of modules. A single unit or stage containing one or a bank ofmembrane modules is adequate for many applications. If the residuestream requires further purification, it may be passed to a second bankof membrane modules for a second processing step. If the permeate streamrequires further concentration, it may be passed to a second bank ofmembrane modules for a second-stage treatment. Such multi-stage ormulti-step processes, and variants thereof, will be familiar to those ofskill in the art, who will appreciate that the membrane separation stepmay be configured in many possible ways, including single-stage,multistage, multistep, or more complicated arrays of two or more unitsin serial or cascade arrangements.

Stream 126 flows across the feed side of the membranes, and sweep gasstream, 130, of air, oxygen-enriched air or oxygen flows across thepermeate side. The gas flow pattern within the membrane modules shouldpreferably, although not necessarily, be such that flow on the permeateside is at least partly or substantially countercurrent to flow on thefeed side.

In membrane gas separation processes, the driving force fortransmembrane permeation is supplied by lowering the partial pressure ofthe desired permeant on the permeate side to a level below its partialpressure on the feed side. The use of the sweep gas stream 130 maintainsa low carbon dioxide partial pressure on the permeate side, therebyproviding driving force.

The partial pressure of carbon dioxide on the permeate side may becontrolled by adjusting the flow rate of the sweep stream. High sweepflow rates will achieve maximum carbon dioxide removal from the membranefeed gas, but a comparatively carbon dioxide dilute permeate stream(that is, comparatively low carbon dioxide enrichment in the sweep gasexiting the modules). Low sweep flow rates will achieve highconcentrations of carbon dioxide in the permeate, but relatively lowlevels of carbon dioxide removal from the feed.

Typically and preferably, the flow rate of the sweep stream should bebetween about 50% and 200% of the flow rate of the membrane feed stream,and most preferably between about 80% and 120%. Often a ratio of about1:1 is convenient and appropriate.

The total gas pressures on each side of the membrane may be the same ordifferent, and each may be above or below atmospheric pressure. If thepressures are about the same, the entire driving force is provided bythe sweep mode operation. Optionally, stream 126 may be supplied to themembrane unit at slightly elevated pressure, by which we mean at apressure of a few bar, such as 2 bar, 3 bar or 5 bar. If this requiresrecompression of stream 126, a portion of the energy used for thecompressors may be recovered by expanding the residue stream, 129, in aturbine.

The membrane separation step divides stream 126 into residue stream 129,which is depleted in carbon dioxide, and permeate/sweep stream 131. Theresidue stream forms the treated flue gas produced by the process, andis usually discharged to the environment via the power plant stack. Thecarbon dioxide content of this stream is preferably less than about 5vol %; more preferably less than about 2 vol %, and most preferably nogreater than about 1 vol %.

The permeate/sweep stream, 131, preferably containing at least 10 vol %carbon dioxide, and more preferably at least about 15 vol % carbondioxide, is withdrawn from the membrane unit and is passed to the firstcompression unit, 101, to form at least part of the air, oxygen-enrichedair or oxygen feed.

Optionally, turbine exhaust stream 119 may be split into a secondportion, and the second portion, indicated by dashed line 120, maybypass the sweep-based membrane separation and be sent with stream 131as stream 133 to the first compression unit, 101, as at least part ofthe air, oxygen-enriched air or oxygen feed.

FIG. 2 shows a representative example using membrane separation for thecarbon dioxide removal step, 105, with heat integration used to cool inthe incoming feed stream. Like elements are numbered as in FIG. 1.

Referring to FIG. 2, first compressed stream 102 is passed throughcooling step 103, as shown in FIG. 1, in this case carried out in twoheat exchange steps, 103 a and 103 b. In step 103 a, stream 102 is runagainst membrane residue stream 108, with stream 108 entering the heatexchanger as indicated as position A and exiting at position B. Heatedstream 108 is then directed to second compression step 109 as describedabove for FIG. 1.

In step 103 b, additional cooling of stream 102 is provided before itpasses as cooled stream 104 to the membrane step, 105, containingmembranes, 235.

An alternative embodiment of the invention is shown in FIG. 3. Air,oxygen-enriched air, or oxygen is introduced into the processes asstream 327 and flows as a sweep stream across the permeate side of thesweep-driven membrane separation unit, 324, discussed in more detailbelow. The permeate stream, 328, comprises both the sweep gas and carbondioxide that has permeated the membranes, 325, and preferably has acarbon dioxide content of at least about 10 vol %, more preferably atleast about 15 vol %, and most preferably at least about 20 vol %.Stream 328 passes, with optional addition of stream 331 and make-up airstream 332, as air intake stream 330, to first compression step, 301.

The first compression step is carried out in one or multiplecompressors, and produces first compressed stream, 302, at a typicalpressure of a few tens of bar, such as 20 bar or 30 bar. Stream 302 isintroduced with a fuel stream, 304, into combustion step or zone, 303.Natural gas, other methane-containing gas, syngas, hydrogen, or anyother fuel capable of burning in air may be used. Combustion produceshot, high-pressure gas stream 313.

In a traditional gas-fired combustion process, the exhaust gas from thecombustor typically contains about 4 or 5 vol % carbon dioxide. In ourprocess, carbon dioxide is recycled via stream 328/330, as discussed inmore detail below. As a result, the concentration of carbon dioxide instream 313 is higher than in a traditional nature gas-fired plant, andis frequently as high as at least about 10 vol %, or even at least 15vol %, 20 vol %, or more.

A portion of the turbine exhaust stream, 329, is sent to a secondcompression step, 305. The second compression step is carried out in oneor multiple compressors, and produces second compressed stream, 306, ata typical pressure between 2-10 bar, preferably about 5 bar, morepreferably about 2 bar. Stream 306 is directed to a gas separation step,310, where carbon dioxide is captured and removed from the process viastream 311. Depending on the operating temperature of the separationequipment, stream 306 may be cooled by heat exchange or otherwise inoptional cooling step, 307, to produce cooled stream 309. Watercondensed as a result of the cooling may be removed as stream 308.

Various considerations affect the choice of technology and operatingmethodology for step 310. In steady state, the mass of carbon dioxideremoved from the process in streams 311 and 326 equals the mass ofcarbon dioxide generated by combustion. Preferably, at least 50%, andmore preferably at least 80% or 90% of the generated carbon dioxideshould be captured into stream 311.

Nevertheless, very high levels of removal of carbon dioxide from thefeed inlet gas streams 306 or 309 by gas separation are not required,because the off-gas, stream 312, is not vented to the atmosphere, but isdirected to sweep-based membrane separation step 324. The sweep-basedmembrane separation step recycles carbon dioxide in stream 330, so thatthe carbon dioxide concentration in stream 309 tends to be relativelyhigh, such as 15 vol %, 20 vol % or more. Only a portion of thisrecirculating carbon dioxide needs to be removed into stream 311 toachieve the target high levels of carbon dioxide capture. This is asignificant advantage of the process, as step 310 can then be operatedusing relatively low-cost, low-energy options.

Step 310 can be carried out by means of any technology or combination oftechnologies that can create a concentrated carbon dioxide stream fromstream 306 or 309. Representative methods that may be used include, butare not limited to, physical or chemical sorption, membrane separation,compression/low temperature condensation, and adsorption. All of theseare well known in the art as they relate to carbon dioxide removal fromgas mixtures of various types. However, based on the considerationsdiscussed above, the preferred technologies are absorption and membraneseparation.

Step 310 produces a concentrated carbon dioxide stream, 311, which iswithdrawn from the process. In addition to meeting the specifiedpreferred capture targets, this stream has a relatively high carbondioxide concentration, and preferably contains greater than 60 or 70 vol% carbon dioxide. Most preferably, this stream contains at least about80 vol % carbon dioxide. Thus, unusually, the process achieves in onestream both high levels of carbon dioxide capture and high carbondioxide concentration.

After withdrawal from the process, stream 311 may pass to any desireddestination. The high concentration facilitates liquefaction, transport,pipelining, injection and other forms of sequestration.

The off-gas stream, 312, from the carbon dioxide removal or capture stepstill contains carbon dioxide, but at a lower concentration than thecompressed gas stream, 306/309. Typically, but not necessarily, thisconcentration is at least about 5 vol %, and can be up to about 10 vol %or even more.

Stream 312 is sent as an air intake stream to a third compression step,314. Optionally, it may be preferred that a portion of second compressedstream, 333, bypasses cooling step 307 and gas separation step 310, andis mixed with membrane residue stream 312 to form air intake stream 335before entering second compression step 314. In a membrane gasseparation process where carbon dioxide removal is only 40-70% of thecarbon dioxide in the gas, the bypass is closed. In an amine processwhere carbon dioxide removal is about 90%, then the bypass is partiallyopen and only a bit of the first compressed stream goes to theseparation unit.

The third compression step is carried out in one or multiplecompressors, and produces third compressed stream, 315, at a typicalpressure of a few tens of bar, such as 20 bar or 30 bar.

Stream 315 is combined with combusted gas stream 313, and to produce aworking gas stream, 316, that is introduced into gas turbine section,317. This section contains one or more gas turbines, which are coupledby means of shaft, 318, to compressor(s) 301, 305, and 314 and toelectricity generator, 319. The working gas drives the gas turbines,which in turn drive the generator and produce electric power.

The low-pressure exhaust gas from the turbines, stream 317, is stillhot, and is optionally and preferably directed to a heat recovery steamgenerator, 321. This section includes a boiler that produces steam,stream 322, which can be directed to a steam turbine (not shown). Gasexiting the steam generator, stream 323, is routed as feed gas tosweep-based membrane separation step, 324. If it is necessary to coolthe turbine exhaust gas before passing it to the membrane unit, this maybe done by heat exchange or otherwise in a cooling step (not shown).After passing through optional HRSG, 321, an optional cooling step, orboth, the turbine exhaust stream now passes as feed stream, 323, tosweep-based membrane separation step 324.

Step 324 is carried out using membranes, 325, that are selective infavor of carbon dioxide over oxygen and nitrogen. It is preferred thatthe membranes provide a carbon dioxide/nitrogen selectivity of at leastabout 10, and most preferably at least about 20 under the operatingconditions of the process. A carbon dioxide/oxygen selectivity of atleast 10 or 20 is also preferred. A carbon dioxide permeance of at leastabout 300 gpu, more preferably at least about 500 gpu and mostpreferably at least about 1,000 gpu is desirable. The permeance does notaffect the separation performance, but the higher the permeance, theless membrane area will be required to perform the same separation.

Any membrane with suitable performance properties may be used. Manypolymeric materials, especially elastomeric materials, are verypermeable to carbon dioxide. Preferred membranes for separating carbondioxide from nitrogen or other inert gases have a selective layer basedon a polyether. A number of such membranes are known to have high carbondioxide/nitrogen selectivity, such as 30, 40, 50 or above. Arepresentative preferred material for the selective layer is Pebax®, apolyamide-polyether block copolymer material described in detail in U.S.Pat. No. 4,963,165.

The membrane may take the form of a homogeneous film, an integralasymmetric membrane, a multilayer composite membrane, a membraneincorporating a gel or liquid layer or particulates, or any other formknown in the art. If elastomeric membranes are used, the preferred formis a composite membrane including a microporous support layer formechanical strength and a rubbery coating layer that is responsible forthe separation properties.

The membranes may be manufactured as flat sheets or as fibers and housedin any convenient module form, including spiral-wound modules,plate-and-frame modules and potted hollow-fiber modules. The making ofall these types of membranes and modules is well known in the art. Weprefer to use flat-sheet membranes in spiral-wound modules.

Step 324 may be carried out in a single bank of membrane modules or anarray of modules. A single unit or stage containing one or a bank ofmembrane modules is adequate for many applications. If the residuestream requires further purification, it may be passed to a second bankof membrane modules for a second processing step. If the permeate streamrequires further concentration, it may be passed to a second bank ofmembrane modules for a second-stage treatment. Such multi-stage ormulti-step processes, and variants thereof, will be familiar to those ofskill in the art, who will appreciate that the membrane separation stepmay be configured in many possible ways, including single-stage,multistage, multistep, or more complicated arrays of two or more unitsin serial or cascade arrangements.

Stream 323 flows across the feed side of the membranes, and sweep gasstream, 327, of air, oxygen-enriched air or oxygen flows across thepermeate side. The gas flow pattern within the membrane modules shouldpreferably, although not necessarily, be such that flow on the permeateside is at least partly or substantially countercurrent to flow on thefeed side.

In membrane gas separation processes, the driving force fortransmembrane permeation is supplied by lowering the partial pressure ofthe desired permeant on the permeate side to a level below its partialpressure on the feed side. The use of the sweep gas stream 327 maintainsa low carbon dioxide partial pressure on the permeate side, therebyproviding driving force.

The partial pressure of carbon dioxide on the permeate side may becontrolled by adjusting the flow rate of the sweep stream. High sweepflow rates will achieve maximum carbon dioxide removal from the membranefeed gas, but a comparatively carbon dioxide dilute permeate stream(that is, comparatively low carbon dioxide enrichment in the sweep gasexiting the modules). Low sweep flow rates will achieve highconcentrations of carbon dioxide in the permeate, but relatively lowlevels of carbon dioxide removal from the feed.

Typically and preferably, the flow rate of the sweep stream should bebetween about 50% and 200% of the flow rate of the membrane feed stream,and most preferably between about 80% and 120%. Often a ratio of about1:1 is convenient and appropriate.

The total gas pressures on each side of the membrane may be the same ordifferent, and each may be above or below atmospheric pressure. If thepressures are about the same, the entire driving force is provided bythe sweep mode operation. Optionally, stream 323 may be supplied to themembrane unit at slightly elevated pressure, by which we mean at apressure of a few bar, such as 2 bar, 3 bar or 5 bar. If this requiresrecompression of stream 323, a portion of the energy used for thecompressors may be recovered by expanding the residue stream, 326, in aturbine.

The membrane separation step divides stream 323 into residue stream,326, depleted in carbon dioxide, and permeate/sweep stream, 328. Theresidue stream forms the treated flue gas produced by the process, andis usually discharged to the environment via the power plant stack. Thecarbon dioxide content of this stream is preferably less than about 5vol %; more preferably less than about 2 vol %, and most preferably nogreater than about 1 vol %.

The permeate/sweep stream, 328, preferably containing at least 10 vol %carbon dioxide, and more preferably at least about 15 vol % carbondioxide, is withdrawn from the membrane unit and is passed to thecompression unit to form at least part of the air, oxygen-enriched airor oxygen feed.

Turbine exhaust stream 320/323 is split into a second portion, stream329, which bypasses the sweep-based membrane separation and is sent tothe second compression unit, 305.

Optionally, turbine exhaust stream 320/323 may be split into a thirdportion, indicated by dashed line 331, which may bypass the sweep-basedmembrane separation and be sent with stream 328 to the first compressionunit 301 as at least part of the air, oxygen-enriched air or oxygenfeed.

The invention is now illustrated in further detail by specific examples.These examples are intended to further clarify the invention, and arenot intended to limit the scope in any way.

EXAMPLES

All calculations were performed with a modeling program, ChemCad 6.3(ChemStations, Inc., Houston, Tex.), containing code for the membraneoperation developed by MTR's engineering group, For the calculations,all compressors and vacuum pumps were assumed to be 85% efficient. Ineach case, the calculation was normalized to a combustion processproducing 1 ton/hour of carbon dioxide.

It was further assumed that a membrane separation unit was used as thecarbon capture unit.

Example 1: Molten Salt Membranes Used for Gas Separation Step, TwoCompressor Loops (not in Accordance with the Invention)

As a comparative example, a computer calculation was performed to modelthe performance of the process with the design shown in FIG. 4. Eachcompressor was assumed to deliver a compressed gas at 30 bara. The ratioof turbine exhaust gas directed to the sweep unit to gas directed tocompression step 401 b was set at 3:1. Molten salt membranes wereassumed to be used for step 412. The permeate side of the membranes wasassumed to be at 2 bara.

The results of the calculation are shown in Table 1.

TABLE 1 Stream 416 428 406 445 444 419 425 413 429 Molar 22 302 401 119123 521 357 25 259 flow (kmol/h) Temp 38 15 25 25 375 634 25 374 11 (°C.) Pressure 30 1 1 2 30 1 2 2 1 (bara) Component (vol %) Oxygen 0 20.715 4.5 4.5 4.2 4.5 1.1 7.2 Nitrogen 1.6 77.3 62.1 69.6 68.8 63.6 70.08.6 90.3 Carbon 1.0 0 20.4 23.5 24.3 21.4 23.5 90.3 0.8 dioxide Methane93.1 0 0 0 0 0 0 0 0 Water 0 1.0 1.8 1.5 1.5 10.0 1.5 0 0.5 Argon 0 1.00.7 0.8 0.8 0.8 0.8 0 1.1 Ethane 3.2 0 0 0 0 0 0 0 0 Prop 0.7 0 0 0 0 00 0 0 n-butane 0.4 0 0 0 0 0 0 0 0

The process produces a stack gas containing 0.8 vol % carbon dioxide,and a concentrated product stream containing about 90 vol % carbondioxide. The process requires a membrane area of about 74 m² for themolten salt membranes, which removes 82% of the carbon dioxide in gasstream 444, and a membrane area of about 1,430 m² for the sweep-basedunit.

Example 2: Embodiment of FIG. 1, Feed Gas Pressure at 5 Bar for the GasSeparation Step

A calculation was performed to model the performance of the process ofthe invention shown in FIG. 1 where the feed gas to the gas separationstep, 106, is compressed to a pressure of 5 bar by compression step 101.

For the calculation, the feed gas stream 104 was calculated to have aflow rate of 16,557 kg/hour and contain nitrogen, oxygen, carbon dioxideand water. It was also calculated that the molar compositions wereapproximately as follows:

Nitrogen: 74.4%

Oxygen 14.4%

Carbon dioxide: 10.4%

Water: 0.8%

It was assumed that a portion of the exhaust gas 119 was used as aninternal recycle as stream 120.

The results of the calculations are shown in Table 2.

TABLE 2 Stream 104 107 108 111 119 120 129 130 135 Total Mass 16,5571,018 15,539 371 15,527 3,494 9,642 11,050 15,539 Flow (kg/h) Temp (°C.) 30 30 30 30 35 35 30 30 30 Pressure (bara) 5.0 0.2 5.0 30.0 1.1 1.11.1 0.9 1.0 Component (mol %) Nitrogen 74.4 17.0 77.3 0.5 77.1 7.1 88.679.0 71.6 Oxygen 14.4 6.5 14.8 0.0 6.0 6.0 9.8 21.0 13.8 Carbon 10.468.8 7.4 0.1 11.8 11.8 1.3 0.0 10.0 Dioxide Water 0.8 7.7 0.5 0.0 5.15.1 0.3 0.0 4.6 Methane 0.0 0.0 0.0 98.2 0.0 0.0 0.0 0.0 0.0 C₂₊ 0.0 0.00.0 1.2 0.0 0.0 0.0 0.0 0.0 Hydrocarbons

The process produces a stack gas containing 1.3% carbon dioxide, and aconcentrated product stream containing about 69% carbon dioxide. Theprocess achieves a carbon dioxide recovery of 80%. The membrane areaused for step 106 was 198 m² and the membrane area required for step 127was 10,000 m².

Example 3: Embodiment of FIG. 1, Feed Gas Pressure at 2 Bar for the GasSeparation Step

A calculation was performed to model the performance of the process ofthe invention shown in FIG. 1 where the feed gas to the gas separationstep, 106, is compressed to a pressure of 2 bar by compression step 101.

For the calculation, the feed gas stream 104 was calculated to have aflow rate of 16,354 kg/hour and contain nitrogen, oxygen, carbon dioxideand water. It was also calculated that the molar compositions wereapproximately as follows:

Nitrogen: 70.9%

Oxygen 14.8%

Carbon dioxide: 12.2%

Water: 2.1%

It was assumed that a portion of the exhaust gas 119 was used as aninternal recycle as stream 120.

The results of the calculations are shown in Table 3.

TABLE 3 Stream 104 107 108 111 119 120 129 130 135 Total Mass 16,354 81115,543 372 15,414 3,237 9,560 10,742 16,593 Flow (kg/h) Temp (° C.) 3030 30 30 35 35 30 30 43 Pressure (bara) 2.0 0.2 2.0 1.0 1.1 1.0 1.1 0.91.0 Component (mol %) Nitrogen 70.9 17.6 73.1 0.5 73.9 73.9 87.4 79.069.2 Oxygen 14.8 7.1 15.1 0.0 6.3 6.3 9.3 21.0 14.4 Carbon 12.2 62.010.2 0.1 14.7 14.7 2.8 0.0 12.0 Dioxide Water 2.1 13.3 1.6 0.0 5.1 5.10.5 0.0 4.4 Methane 0.0 0.0 0.0 98.2 0.0 0.0 0.0 0.0 0.0 C₂₊ 0.0 0.0 0.01.2 0.0 0.0 0.0 0.0 0.0 Hydrocarbons

The process produces a stack gas containing about 3% carbon dioxide, anda concentrated product stream containing about 62% carbon dioxide. Theprocess achieves a carbon dioxide recovery of 60%. The membrane areaused for step 106 was 456 m² and the membrane area required for step 127was 6,000 m².

Example 4: Embodiment of FIG. 3, Three Compressor Loops

A calculation was performed to model the performance of the process ofthe invention using three compressors in accordance with the designshown in FIG. 3. The feed gas to the gas separation step, 310, wascompressed to a pressure of 2 bar by compression step 305.

For the calculation, the feed gas stream 309 was calculated to have aflow rate of 16,354 kg/hour and contain nitrogen, oxygen, carbon dioxideand water. It was also calculated that the molar compositions wereapproximately as follows:

Nitrogen: 70.9%

Oxygen 14.8%

Carbon dioxide: 12.2%

Water: 2.1%

It was assumed that a portion of the exhaust gas 323 was used as aninternal recycle as stream, 331.

The results of the calculations are shown in Table 4.

TABLE 4 Stream 309 311 312 320 329 331 326 327 330 Total Mass 6,920 7446,176 15,175 6,980 819 5,978 7,111 6,980 Flow (kg/h) Temp (° C.) 30 3030 33 33 35 30 30 32 Pressure (bara) 2.0 0.2 2.0 1.1 1.1 1.1 1.1 0.9 1.0Component (mol %) Nitrogen 80.9 18.4 86.7 79.7 79.7 79.7 92.1 79.0 79.7Oxygen 1.1 0.5 1.2 1.1 1.1 1.1 2.9 21.0 1.1 Carbon 15.9 69.8 10.9 15.715.7 15.7 4.5 0.0 15.7 Dioxide Water 2.1 11.3 1.2 3.5 3.5 3.5 0.5 0.03.5

The process produces a stack gas containing about 4.5% carbon dioxide,and a concentrated product stream containing about 70% carbon dioxide.The process also achieves a carbon dioxide recovery of 60%. The membranearea used for step 310 was 360 m² and the membrane area required forstep 324 was 2,000 m².

We claim:
 1. A process for controlling carbon dioxide exhaust from acombustion process, comprising: (a) compressing an oxygen-containingstream in a first compression apparatus, thereby producing a firstcompressed gas stream; (b) compressing a carbon dioxide-containingstream in a second compression apparatus, thereby producing a secondcompressed gas stream; (c) combusting the first compressed gas streamwith a gaseous fuel in a combustion apparatus, thereby producing acombusted gas stream; (d) routing at least a portion of the secondcompressed gas stream to a gas separation apparatus adapted toselectively remove carbon dioxide, thereby producing a carbondioxide-enriched stream and a carbon dioxide-depleted stream; (e)compressing the carbon dioxide-depleted stream in a third compressionapparatus, thereby producing a third compressed gas stream; (f) routingthe combusted gas stream and the third compressed gas stream as part ofa working gas stream to a gas turbine apparatus mechanically coupled toan electricity generator, and operating the gas turbine apparatus,thereby generating electric power and producing a turbine exhauststream; (g) passing a first portion of the turbine exhaust stream backto the second compression apparatus as at least a portion of the carbondioxide-containing stream; (h) passing at least a second portion of theturbine exhaust stream to a membrane separation step, wherein themembrane separation step comprises: (i) providing a membrane having afeed side and a permeate side, and being selectively permeable to carbondioxide over nitrogen and to carbon dioxide over oxygen, (ii) passing athird portion of the turbine exhaust stream across the feed side, (iii)passing air, oxygen-enriched air, or oxygen as a sweep stream across thepermeate side, (iv) withdrawing from the feed side a residue stream thatis depleted in carbon dioxide compared to the turbine exhaust stream,and (v) withdrawing from the permeate side a permeate stream comprisingoxygen and carbon dioxide; and (vi) passing the permeate stream to step(a) as at least a portion of the oxygen-containing stream.
 2. Theprocess of claim 1, wherein the gas separation apparatus is selectedfrom the group consisting of absorption, adsorption, liquefaction, andmembrane separation.
 3. The process of claim 2, wherein the gasseparation apparatus is membrane separation.
 4. The process of claim 3,wherein the membrane separation apparatus incorporates polymericmembranes.
 5. The process of claim 1, further comprising the step ofpassing the third portion of the turbine exhaust stream to step (a) asat least a part of the oxygen-containing gas before carrying out step(g).
 6. The process of claims 1 or 5, further comprising the step ofrouting the turbine exhaust stream in (f) to a heat recovery steamgenerator before carrying out step (g).
 7. The process of claim 1,further comprising the step of cooling the turbine exhaust stream (f)before carrying out step (g).
 8. The process of claim 1, wherein theresidue stream has a carbon dioxide concentration of less than 5 vol %.9. The process of claim 1, wherein the second compressed gas stream iswithdrawn from the second compression apparatus at a pressure within therange of about 2 bar to about 10 bar.
 10. The process of claim 1,wherein the first compressed gas stream is withdrawn from the firstcompression apparatus at about 30 bar.
 11. The process of claim 1,further comprising cooling the second compressed gas stream to atemperature of about 30-100° C. prior to step (d).
 12. The process ofclaim 1, wherein the gaseous fuel comprises natural gas.
 13. The processof claim 1, wherein a second portion of the second compressed stream ismixed with the carbon dioxide-depleted stream from step (d) prior tostep (e).